UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended Sept. 30, 2010

or

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number: 001-03789

Southwestern Public Service Company

(Exact name of registrant as specified in its charter)

New Mexico	75-0575400
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
Tyler at Ninth
Amarillo, Texas	79101
(Address of principal executive offices)	(Zip Code)

(303) 571-7511

 (Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   x Yes o No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 and Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).   o Yes o No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o	Accelerated filer o
Non-accelerated filer x	Smaller reporting company o
(Do not check if smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).   o Yes x No

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

Class	Outstanding at Nov. 1, 2010
Common Stock, $1 par value	100 shares

Southwestern Public Service Company meets the conditions set forth in General Instruction H (1)(a) and (b) of Form 10-Q and is therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H (2) to such Form 10-Q.

TABLE OF CONTENTS

PART I - FINANCIAL INFORMATION
Item l.	Financial Statements (Unaudited)	3
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	17
Item 4.	Controls and Procedures	20
PART II - OTHER INFORMATION
Item 1.	Legal Proceedings	20
Item 1A.	Risk Factors	21
Item 6.	Exhibits	22
SIGNATURES		23
Certifications Pursuant to Section 302		1
Certifications Pursuant to Section 906		1
Statement Pursuant to Private Litigation		1

This Form 10-Q is filed by Southwestern Public Service Company, a New Mexico corporation (SPS). SPS is a wholly owned subsidiary of Xcel Energy Inc. (Xcel Energy). Additional information on Xcel Energy is available on various filings with the Securities and Exchange Commission (SEC).

2

PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

SOUTHWESTERN PUBLIC SERVICE COMPANY

STATEMENTS OF INCOME (UNAUDITED)

(amounts in thousands of dollars)

	Three Months Ended Sept. 30,						Nine Months Ended Sept. 30,
	2010			2009			2010			2009
Operating revenues	$	467,424		$	397,094		$	1,247,355		$	1,094,217
Operating expenses
Electric fuel and purchased power		288,386			229,607			788,089			673,126
Other operating and maintenance expenses		61,807			52,716			180,794			161,145
Demand side management program expenses		3,393			2,673			8,386			6,646
Depreciation and amortization		26,083			25,970			77,391			76,524
Taxes (other than income taxes)		10,818			9,458			30,879			29,231
Total operating expenses		390,487			320,424			1,085,539			946,672
Operating income		76,937			76,670			161,816			147,545
Other income (expense), net		(82	)		(538	)		31			(496	)
Allowance for funds used during construction – equity		1,085			887			2,529			2,977
Interest charges and financing costs
Interest charges – includes other financing costs of $666, $662, $1,975 and $1,989, respectively		16,217			17,178			48,099			50,860
Allowance for funds used during construction – debt		(792	)		(618	)		(2,052	)		(2,063	)
Total interest charges and financing costs		15,425			16,560			46,047			48,797
Income before income taxes		62,515			60,459			118,329			101,229
Income taxes		23,326			23,044			47,045			37,824
Net income	$	39,189		$	37,415		$	71,284		$	63,405

See Notes to Financial Statements

3

SOUTHWESTERN PUBLIC SERVICE COMPANY

STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in thousands of dollars)

	Nine Months Ended Sept. 30,
	2010			2009
Operating activities
Net income	$	71,284		$	63,405
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization		79,094			78,244
Demand side management program amortization expenses		1,573			1,317
Deferred income taxes		26,520			3,745
Amortization of investment tax credits		(223	)		(243	)
Allowance for equity funds used during construction		(2,529	)		(2,977	)
Net realized and unrealized hedging and derivative transactions		201			(1,013	)
Changes in operating assets and liabilities:
Accounts receivable		(25,352	)		9,471
Accrued unbilled revenues		(12,666	)		7,104
Recoverable electric energy costs		(4,978	)		3,978
Inventories		(5,734	)		20,543
Prepayments and other		11,468			(27,133	)
Accounts payable		(19,399	)		(40,945	)
Deferred electric energy costs		(16,430	)		52,547
Net regulatory assets and liabilities		2,134			1,961
Other current liabilities		16,240			11,441
Change in other noncurrent assets		(2,838	)		(8,019	)
Change in other noncurrent liabilities		(2,111	)		(18,110	)
Net cash provided by operating activities		116,254			155,316
Investing activities
Utility capital/construction expenditures		(196,035	)		(148,543	)
Allowance for equity funds used during construction		2,529			2,977
Investments in utility money pool arrangement		(204,200	)		(776,400	)
Receipts from utility money pool arrangement		281,200			776,900
Net cash used in investing activities		(116,506	)		(145,066	)
Financing activities
Borrowings under utility money pool arrangement		61,000			-
Repayment of long-term debt		(25,000	)		(100,027	)
Capital contributions from parent		8,802			13,044
Dividends paid to parent		(50,810	)		(49,813	)
Net cash used in financing activities		(6,008	)		(136,796	)
Net decrease in cash and cash equivalents		(6,260	)		(126,546	)
Cash and cash equivalents at beginning of period		7,363			130,795
Cash and cash equivalents at end of period	$	1,103		$	4,249
Supplemental disclosure of cash flow information:
Cash paid for interest, net of amounts capitalized	$	(43,963	)	$	(37,181	)
Cash paid for income taxes, net		(8,310	)		(58,574	)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	4,075		$	3,545

See Notes to Financial Statements

4

SOUTHWESTERN PUBLIC SERVICE COMPANY

BALANCE SHEETS (UNAUDITED)

(amounts in thousands of dollars)

	Sept. 30, 2010			Dec. 31, 2009
Assets
Current assets
Cash and cash equivalents	$	1,103		$	7,363
Investments in utility money pool arrangement		-			77,000
Accounts receivable, net		73,849			47,065
Accounts receivable from affiliates		3,665			5,097
Accrued unbilled revenues		118,451			105,785
Inventories		32,881			27,147
Recoverable electric energy costs		6,137			1,159
Derivative instruments valuation		7,892			8,926
Deferred income taxes		23,742			36,406
Prepayments and other		4,459			15,927
Total current assets		272,179			331,875
Property, plant and equipment, net		2,371,698			2,260,984
Other assets
Regulatory assets		286,435			286,734
Derivative instruments valuation		66,707			67,625
Other		10,799			8,783
Total other assets		363,941			363,142
Total assets	$	3,007,818		$	2,956,001
Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	44,500		$	-
Borrowings under utility money pool arrangement		61,000			-
Accounts payable		139,942			163,253
Accounts payable to affiliates		10,179			14,625
Deferred electric energy costs		43,353			59,783
Taxes accrued		20,064			18,209
Accrued interest		24,295			12,371
Dividends payable		16,292			17,240
Derivative instruments valuation		3,601			3,588
Other		21,583			20,125
Total current liabilities		384,809			309,194
Deferred credits and other liabilities
Deferred income taxes		547,042			533,241
Deferred investment tax credits		2,169			2,392
Regulatory liabilities		124,653			119,080
Asset retirement obligations		19,715			18,757
Derivative instruments valuation		45,891			48,654
Pension and employee benefit obligations		41,816			44,276
Other		8,672			8,450
Total deferred credits and other liabilities		789,958			774,850
Commitments and contingent liabilities
Capitalization
Long-term debt		853,187			922,447
Common stock – authorized 200 shares of $1.00 par value; outstanding 100 shares		-			-
Additional paid in capital		701,750			692,948
Retained earnings		279,832			258,409
Accumulated other comprehensive loss		(1,718	)		(1,847	)
Total common stockholder’s equity		979,864			949,510
Total liabilities and equity	$	3,007,818		$	2,956,001

See Notes to Financial Statements

5

SOUTHWESTERN PUBLIC SERVICE COMPANY

Notes to Financial Statements (UNAUDITED)

In the opinion of management, the accompanying unaudited financial statements contain all adjustments necessary to present fairly, in accordance with accounting principles generally accepted in the United States of America (GAAP), the financial position of SPS as of Sept. 30, 2010, and Dec. 31, 2009; the results of its operations for the three and nine months ended Sept. 30, 2010 and 2009; and its cash flows for the nine months ended Sept. 30, 2010 and 2009.  All adjustments are of a normal, recurring nature, except as otherwise disclosed.  Management has also evaluated the impact of events occurring after Sept. 30, 2010 up to the date of issuance of these financial statements.  These statements contain all necessary adjustments and disclosures resulting from that evaluation.  The Dec. 31, 2009 balance sheet information has been derived from the audited 2009 financial statements.  These notes to the financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q.  Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations.  For further information, refer to the financial statements and notes thereto included in the SPS Annual Report on Form 10-K for the year ended Dec. 31, 2009, filed with the SEC on March 1, 2010.  Due to the seasonality of SPS’s electric sales, interim results are not necessarily an appropriate base from which to project annual results.

1. Summary of Significant Accounting Policies

Except to the extent updated or described below, the significant accounting policies set forth in Note 1 to the financial statements in SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2009, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

Reclassifications — Demand side management program amortization expenses for the nine months ended Sept. 30, 2009 were reclassified as a separate line item from depreciation and amortization expenses within the statements of cash flows.  The reclassification did not have an impact on net cash provided by operating activities.

2. Accounting Pronouncements

Recently Adopted

Consolidation of Variable Interest Entities — In June 2009, the Financial Accounting Standards Board (FASB) issued new guidance on consolidation of variable interest entities. The guidance affects various elements of consolidation, including the determination of whether an entity is a variable interest entity and whether an enterprise is a variable interest entity’s primary beneficiary. These updates to the FASB Accounting Standards Codification (ASC or Codification) were effective for interim and annual periods beginning after Nov. 15, 2009.  SPS implemented the guidance on Jan. 1, 2010, and the implementation did not have a material impact on its financial statements.  For further information and required disclosures regarding variable interest entities, see Note 6 to the financial statements.

Fair Value Measurement Disclosures — In January 2010, the FASB issued Fair Value Measurements and Disclosures (Topic 820) — Improving Disclosures about Fair Value Measurements (Accounting Standards Update (ASU) No. 2010-06), which updates the Codification to require new disclosures for assets and liabilities measured at fair value. The requirements include expanded disclosure of valuation methodologies for fair value measurements, transfers between levels of the fair value hierarchy, and gross rather than net presentation of certain changes in Level 3 fair value measurements. The updates to the Codification contained in ASU No. 2010-06 were effective for interim and annual periods beginning after Dec. 15, 2009, except for requirements related to gross presentation of certain changes in Level 3 fair value measurements, which are effective for interim and annual periods beginning after Dec. 15, 2010.  SPS implemented the portions of the guidance required on Jan. 1, 2010, and the implementation did not have a material impact on its financial statements.  For further information and required disclosures, see Note 9 to the financial statements.

6

3. Selected Balance Sheet Data

(Thousands of Dollars)	Sept. 30, 2010			Dec. 31, 2009
Accounts receivable, net
Accounts receivable	$	78,727		$	51,480
Less allowance for bad debts		(4,878	)		(4,415	)
	$	73,849		$	47,065
Inventories
Materials and supplies	$	15,989		$	15,737
Fuel		16,892			11,410
	$	32,881		$	27,147
Property, plant and equipment, net
Electric plant	$	3,881,273		$	3,777,623
Construction work in progress		160,821			95,652
Total property, plant and equipment		4,042,094			3,873,275
Less accumulated depreciation		(1,670,396	)		(1,612,291	)
	$	2,371,698		$	2,260,984

4. Income Taxes

Medicare Part D Subsidy Reimbursements — In March 2010, the Patient Protection and Affordable Care Act was signed into law.  The law includes provisions to generate tax revenue to help offset the cost of the new legislation.  One of these provisions reduces the deductibility of retiree health care costs to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D coverage, beginning in 2013.  Based on this provision, SPS is subject to additional taxes and is required to reverse previously recorded tax benefits in the period of enactment.

SPS expensed approximately $1.9 million of previously recognized tax benefits relating to Medicare Part D subsidies during the first quarter of 2010.  SPS does not expect the $1.9 million of additional tax expense to recur in future periods.  The 2010 effective tax rate (ETR) will increase due to additional tax expense of approximately $0.5 million associated with current year retiree health care accruals.

Federal Audit — SPS is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. During the first quarter of 2010, the Internal Revenue Service (IRS) completed an examination of Xcel Energy’s federal income tax returns of tax years 2006 and 2007. The IRS did not propose any material adjustments for those tax years. The statute of limitations applicable to Xcel Energy’s 2006 federal income tax return expired in August 2010.  The statute of limitations applicable to Xcel Energy’s 2007 federal income tax return will expire in September 2011.  The IRS commenced an examination of tax years 2008 and 2009 in the third quarter of 2010.  As of Sept. 30, 2010, the IRS had not proposed any material adjustments to tax years 2008 and 2009.

State Audits — SPS is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Sept. 30, 2010, SPS’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2005. During the second quarter of 2010, the state of Texas completed its audit of tax years 2006 and 2007. No change in tax liability was proposed. There currently are no state income tax audits in progress.

Unrecognized Tax Benefits — The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual ETR. In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the ETR but would accelerate the payment of cash to the taxing authority to an earlier period.

A reconciliation of the amount of unrecognized tax benefit is as follows:

(Millions of Dollars)	Sept. 30, 2010		Dec. 31, 2009
Unrecognized tax benefit - Permanent tax positions	$	0.1	$	0.2
Unrecognized tax benefit - Temporary tax positions		3.6		2.7
Unrecognized tax benefit balance	$	3.7	$	2.9

7

The increase in the unrecognized tax benefit balance of $0.4 million from June 30, 2010 to Sept. 30, 2010 and $0.8 million from Dec. 31, 2009 to Sept. 30, 2010 was due to the addition of uncertain tax positions related to current and prior years’ activity.  SPS’ amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS audit progresses and state audits resume.  At this time, due to the uncertain nature of the audit process, it is not reasonably possible to estimate an overall range of possible change.

5. Rate Matters

Except to the extent noted below, the circumstances set forth in Note 13 to the financial statements included in SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2009 appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

Pending and Recently Concluded Regulatory Proceedings — Public Utility Commission of Texas (PUCT)

Texas Retail Base Rate Case — In May 2010, SPS filed a Texas rate case with the PUCT, seeking an annual base rate increase of approximately $62 million.  On a net basis, the request seeks to increase customer bills by approximately $53.4 million, or 7 percent.  The rate filing is based on a 2009 test year adjusted for known and measurable changes, a requested return on equity (ROE) of 11.35 percent, an electric rate base of $1.031 billion and an equity ratio of 51.0 percent.  The following table summarizes the request:

(Millions of Dollars)	Request
Proposed base rate increase	$	62.0
Franchise fee cost recovery		8.7
Nitrogen oxide emission allowances		0.8
Purchased capacity recovery factor		(13.5	)
Transmission cost recovery factor		(4.6	)
Adjusted rate increase	$	53.4

The filing with the PUCT also includes a request to reconcile SPS’ fuel and purchased power costs for calendar years 2008 and 2009.  As of Dec. 31, 2009, SPS had a fuel cost under-recovery of approximately $3.3 million.

In September 2010, SPS filed an agreement with the intervening parties to abate, or suspend, the procedural schedule for a 90-day extension in this case.  The extension allows time for SPS to receive regulatory approval of the sale of distribution assets to the city of Lubbock, Texas (Lubbock), noted below, and to allow the intervening parties to ascertain the financial impact of the sale.  SPS made a filing on Oct. 19, 2010 showing the on-going savings related to the Lubbock sale.  As part of the agreement to abate the procedural schedule, the parties agreed that the effective date of implementation of SPS’ new rates is expected to be Feb. 16, 2011.  This will be accomplished either by establishing interim rates effective on Feb. 16, 2011; or by making the final rates effective retroactive back to Feb. 16, 2011 from the date SPS implements final rates, after the PUCT issues its final order.  The revised procedural schedule is as follows:

● Intervenor direct testimony due Jan. 18, 2011;

● PUCT staff direct testimony due Jan. 25, 2011;

● PUCT staff and intervenor cross rebuttal testimony due Feb. 1, 2011;

● SPS rebuttal testimony due Feb. 8, 2011; and

● Hearings on Feb. 21, 2011 through March 11, 2011.

Lubbock Electric Distribution Assets— In November 2009, SPS entered into an agreement with Lubbock, in which SPS will sell its electric distribution system assets in Lubbock to Lubbock Power and Light for approximately $87 million.  As part of this transaction, SPS will continue to provide the wholesale power to meet the electric load for the customers that SPS currently serves.  The wholesale power agreements provide for formula rates that change annually based on the actual cost of service.  The formula rate with West Texas Municipal Power Agency (WTMPA) reflects an initial 10.5 percent ROE.  All or portions of this transaction are subject to review and approval by the PUCT, the New Mexico Public Regulation Commission (NMPRC) and the Federal Energy Regulatory Commission (FERC).  It is anticipated that any resulting gain on the sale of assets will be shared with retail customers in Texas, as determined in the Texas retail base rate case discussed above.

The FERC accepted the amended WTMPA full-requirements contract in February 2010.  SPS filed its application before the PUCT in January 2010 for the approvals related to the sale of distribution assets to Lubbock.  In June 2010, an uncontested settlement was filed resolving all issues in the Texas proceeding relating to the transaction.  The PUCT approved the uncontested settlement in August 2010.

8

In June 2010, SPS filed its application in New Mexico for approval of the transaction.  Settlement has been reached with all the parties.  A decision and order approving the settlement was issued by the NMPRC in October 2010.  The transaction is expected to close in late October or early November 2010.

Pending and Recently Concluded Regulatory Proceedings — FERC

Transmission Formula Rate Case — In December 2007, SPS filed a transmission formula rate with the FERC.  The FERC accepted the filing, initiated settlement and hearing procedures, and interim rates went into effect on July 6, 2008, subject to refund.  An uncontested, partial settlement was reached in September 2009.  The settlement, including an 11.27 percent ROE and a future test year, was approved by the FERC in December 2009.  The remaining cost allocation of the radial transmission lines issue was resolved by a settlement filed in June 2010, where the expense of the Cap Rock Energy Corporation (Cap Rock) 230 kilovolt (KV) lines was assigned to overall transmission facilities and not directly assigned to Cap Rock.  This is subject to a future change in configuration of the 230 KV lines.  The radial line settlement was approved by the FERC in August 2010.

Wholesale Rate Complaints — In November 2004, Golden Spread Electric, Lyntegar Electric, Farmer’s Electric, Lea County Electric, Central Valley Electric and Roosevelt County Electric, all wholesale cooperative customers of SPS, filed a rate complaint with the FERC alleging that SPS’ rates for wholesale service were excessive and that SPS had incorrectly calculated monthly fuel cost adjustment charges to such customers (the complaint).  Cap Rock, another full-requirements customer of SPS, Public Service Company of New Mexico (PNM) and Occidental Permian Ltd. and Occidental Power Marketing, L.P. (Occidental), SPS’ largest retail customer, intervened in the proceeding.

In April 2008, the FERC issued its order on the complaint applied to the remaining non-settling parties.  In July 2008, SPS submitted its compliance report to the FERC and calculated the base rate refund for the 18-month period to be $6.1 million and the fuel refund to be $4.4 million.  Several wholesale customers protested these calculations.  As of Sept. 30, 2010, SPS has accrued an amount it believes is sufficient to cover the estimated refund obligation related to these complaints.  The status of various settlements and the applicable regulatory approvals are discussed below.  At this time, PNM, which filed a separate complaint, is the only party that has not settled.

Golden Spread Complaint Settlement — SPS reached a settlement with Golden Spread (which included Lyntegar Electric) and Occidental in December 2007 regarding base rate and fuel issues raised in the complaint described above as well as a subsequent rate proceeding.  The FERC approved the settlement in April 2008.  The PUCT and NMPRC approvals were obtained in the first quarter of 2010 eliminating the potential contingent payments by SPS resulting from an adverse cost assignment decision or a failure to obtain state approvals.

New Mexico Cooperatives’ Complaint Settlement — In June 2010, the FERC approved the settlement with Farmers’ Electric Cooperative of New Mexico, Lea County Electric Cooperative, Central Valley Electric Cooperative and Roosevelt County Electric Cooperative, and Occidental.  The settlement resolves all issues arising from the complaint docket and implements a replacement contract with a formula production rate at 10.5 percent ROE and extended the term of its requirements sale to the four wholesale customers.

The four wholesale customers must reduce their power purchases by 90 to 100 megawatts (MW) in 2012, and implement staged reductions in system average cost power purchases through the term of the agreement, which terminates in May 2026.  The settlement made the replacement contract contingent on certain state approvals, which were obtained by SPS.  In the event that all state regulatory approvals had not been received, the settlement included a one time contingent payment of $12 million by SPS to these wholesale customers.

These wholesale customers agreed to hold SPS harmless from any future adverse regulatory treatment regarding the proposed wholesale power sale.  As a result of the FERC approval of the settlement and resolution of the complaint with the New Mexico cooperatives, SPS released previously established reserves of $11.5 million in the second quarter of 2010.

The New Mexico parties and NMPRC staff filed a stipulation to resolve the NMPRC proceeding.  The NMPRC issued a final order approving the stipulation in August 2010.  The PUCT approved the settlement replacement arrangement in September 2010.

Cap Rock Complaint Settlement— In July 2010, SPS and Cap Rock filed a settlement agreement with the FERC.  Subject to FERC approval of the settlement agreement, SPS will pay Cap Rock $1 million to resolve all remaining base rate and fuel claims against SPS.  Cap Rock also agrees that its production base rates will be converted to a formula rate design.  The complaint settlement agreement is still pending FERC approval.

9

6. Commitments and Contingent Liabilities

Except to the extent noted below and in Note 5 to the financial statements in this Quarterly Report on Form 10-Q, the circumstances set forth in Notes 13 and 14 to the financial statements in SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2009, appropriately represent, in all material respects, the current status of commitments and contingent liabilities and are incorporated herein by reference.  The following include commitments, contingencies and unresolved contingencies that are material to SPS’ financial position.

Commitments

Variable Interest Entities— Effective Jan. 1, 2010, SPS adopted new guidance on consolidation of variable interest entities contained in ASC 810 Consolidation.  The guidance requires enterprises to consider the activities that most significantly impact an entity’s financial performance, and power to direct those activities, when determining whether an entity is a variable interest entity and whether an enterprise is a variable interest entity’s primary beneficiary.

Purchased Power Agreements — SPS has entered into agreements with other utilities and energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance or during outages, and meet operating reserve obligations.

SPS has various pay-for-performance contracts with expiration dates through the year 2033.  In general, these contracts provide for energy payments based on actual power taken under the contracts as well as capacity payments.  Capacity payments are typically contingent on the independent power producing entity meeting certain contract obligations, including plant availability requirements.  Certain contractual payments are adjusted based on market indices; however, the effects of price adjustments are mitigated through purchased energy cost recovery mechanisms.

Certain purchased power agreements that either require SPS to reimburse independent power producing entities for natural gas fuel costs, or which contain tolling arrangements under which SPS procures the natural gas required to produce the energy that SPS purchases, have been determined by SPS to create variable interests in the independent power producing entities.  Therefore, certain independent power producing entities are variable interest entities.

SPS purchases power from independent power producing entities that own natural gas fueled power plants.  Under certain purchased power agreements with these entities, SPS is required to reimburse natural gas fuel costs, or to participate in tolling arrangements under which SPS procures the natural gas required to produce the energy that SPS purchases.  These purchased power agreements have been determined by SPS to create variable interests in the independent power producing entities; therefore, certain independent power producing entities are variable interest entities.

SPS is not subject to risk of loss from the operations of these entities, and no significant financial support has been, or is in the future required to be provided other than contractual payments for energy and capacity set forth in purchased power agreements.

SPS has evaluated each of these variable interest entities for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over O&M, historical and estimated future fuel and electricity prices, and financing activities.  SPS has concluded that these entities are not required to be consolidated in its financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance.  As of Sept. 30, 2010 and Dec. 31, 2009, SPS had approximately 1,027 MW of capacity under long-term purchased power agreements with entities that have been determined to be variable interest entities.

Fuel Contracts — SPS purchases all of its coal requirements for its Harrington and Tolk electric generating stations from TUCO, Inc. (TUCO) under contracts for those facilities that expire in 2016 and 2017, respectively.  TUCO arranges for the purchase, receiving, transporting, unloading, handling, crushing, weighing, and delivery of coal to meet SPS’ requirements.  TUCO is responsible for negotiating and administering contracts with coal suppliers, transporters and handlers.

No significant financial support has been, or is in the future, required to be provided to TUCO by SPS, other than contractual payments for delivered coal.  However, the fuel contracts have been determined to create a variable interest in TUCO due to SPS’ reimbursement of certain fuel procurement costs, and therefore TUCO is a variable interest entity.  SPS has concluded that it is not the primary beneficiary of TUCO because SPS does not have the power to direct the activities that most significantly impact TUCO’s economic performance.

10

Environmental Contingencies

SPS has been, or is currently, involved with the cleanup of contamination from certain hazardous substances at several sites.  In many situations, SPS believes it will recover some portion of these costs through insurance claims.  Additionally, where applicable, SPS is pursuing, or intends to pursue, recovery from other potentially responsible parties (PRPs) and through the rate regulatory process.  New and changing federal and state environmental mandates can also create added financial liabilities for SPS, which are normally recovered through the rate regulatory process.  To the extent any costs are not recovered through the options listed above, SPS would be required to recognize an expense

Site Remediation — SPS must pay all or a portion of the cost to remediate sites where past activities of SPS or other parties have caused environmental contamination.  Environmental contingencies could arise from various situations, including third party sites, for which SPS is alleged to be a PRP that sent hazardous materials and wastes.  At Sept. 30, 2010 and Dec. 31, 2009, the liability for the cost of remediating these sites was estimated to be $0.1 million.

Third Party and Other Environmental Site Remediation

Asbestos Removal — Some of SPS’ facilities contain asbestos.  Most asbestos will remain undisturbed until the facilities that contain it are demolished or renovated.  SPS has recorded an estimate for final removal of the asbestos as an asset retirement obligation.  See additional discussion of asset retirement obligations in Note 14 of the SPS Annual Report on Form 10-K for the year ended Dec. 31, 2009.  It may be necessary to remove some asbestos to perform maintenance or make improvements to other equipment.  The cost of removing asbestos as part of other work is immaterial and is recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition projects.

Other Environmental Requirements

Environmental Protection Agency (EPA) Greenhouse Gas (GHG) Rulemaking — In December 2009, in response to the U.S. Supreme Court’s decision in Massachusetts v. EPA, 549 U.S. 497 (2007), the EPA issued its “endangerment” finding that GHG emissions endanger public health and welfare and that emissions from motor vehicles contribute to the GHGs in the atmosphere.  The EPA has promulgated permit requirements for GHGs for large new and modified stationary sources, such as power plants.  These regulations will become applicable in 2011.

Clean Air Interstate Rule (CAIR) — In March 2005, the EPA issued the CAIR to further regulate sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions.  The objective of CAIR is to cap emissions of SO2 and NOx in the eastern United States, including Texas.  In 2008, the U.S. Court of Appeals for the District of Columbia vacated and remanded CAIR.  In July 2010, the EPA issued the proposed Clean Air Transport Rule (CATR), which would replace CAIR by requiring SO2 and NOx reductions in 31 states and the District of Columbia.  The EPA is proposing to reduce these emissions through federal implementation plans for each affected state.  The EPA's preferred approach would set emission limits for each state and allow limited interstate emissions trading.  As proposed, CATR will impact operations in Texas in the form of ozone season NOx emission allowances.  SPS is analyzing the proposed rule to determine whether emission reductions are needed from facilities.  Until CATR becomes final, SPS will continue activities to support CAIR compliance.

Under CAIR’s cap and trade structure, SPS can comply through capital investments in emission controls or purchase of emission allowances from other utilities making reductions on their systems.  The remaining scheduled capital investments for NOx controls in the SPS region are estimated at $16.4 million.  For 2009, the NOx allowance compliance costs were $1.7 million.  The estimated NOx allowance cost for 2010 is $0.5 million.  Annual purchases of SO2 allowances are estimated up to $4.5 million each year, beginning in 2013, for phase I.  If CATR is implemented as proposed then no SO2 allowances would be purchased since CATR replaces CAIR.  SPS believes the cost of any required capital investment or allowance purchases will be recoverable from customers in rates.

Clean Air Mercury Rule (CAMR) — In March 2005, the EPA issued the CAMR, which regulated mercury emissions from power plants.  The Texas Commission on Environmental Quality (TCEQ) adopted by reference the EPA model program.  In February 2008, the U.S. Court of Appeals for the District of Columbia vacated the CAMR, which impacted federal CAMR requirements, but not necessarily state-only mercury legislation and rules.  The EPA has agreed to finalize Maximum Achievable Control Technology emission standards for all hazardous air pollutants from electric utility steam generating units by November 2011 to replace the CAMR.  SPS anticipates that the EPA will require affected facilities to demonstrate compliance within three to five years.  At this time, Texas has not adopted any state-only mercury requirements.

11

Regional Haze Rules — In June 2005, the EPA finalized amendments to the July 1999 regional haze rules.  These amendments apply to the provisions of the regional haze rule that require emission controls, known as best available retrofit technology (BART), for industrial facilities emitting air pollutants that reduce visibility by causing or contributing to regional haze.  Some of SPS’ generating facilities will be subject to BART requirements.  Some of these facilities are located in regions where CAIR is effective.  The TCEQ had determined that facilities may use CAIR as a substitute for BART for NOx and SO2.

Proposed Coal Ash Regulation —  In June 2010, the EPA published a proposed rule seeking comment on whether to regulate coal combustion byproducts (often referred to as coal ash) as a special waste (subject to many of the requirements for hazardous waste) or as a solid (nonhazardous) waste.  Coal ash is currently exempt from hazardous waste regulation.  The EPA’s proposal would result in more comprehensive and expensive requirements related to management and disposal of coal ash.  The EPA has extended the public comment period on the proposed rule until Nov. 19, 2010.  The EPA is also seeking comment on what regulations are appropriate for the beneficial reuse of coal ash.  The timing, scope and potential cost of any final rule that might be implemented are not determinable at this time.

Cunningham Draft Compliance Order — On Feb. 18, 2010, SPS received a draft compliance order from the New Mexico Environment Department (NMED) for Cunningham Station.  In the draft order, NMED alleges that Cunningham exceeded its permit limits for NOx on 7,336 occasions and failed to report these exceedances as required by its permit.  The draft order included a proposed penalty of $16.1 million.  On Sept. 28, 2010, the NMED issued a final compliance order, which reduced the alleged NOx exceedances to approximately 4,000 occasions and the proposed penalty to $7.6 million.  SPS intends to request an administrative hearing to contest the order.

Legal Contingencies

Lawsuits and claims arise in the normal course of business. Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition of them. The ultimate outcome of these matters cannot presently be determined. Accordingly, the ultimate resolution of these matters could have a material adverse effect on SPS’ financial position and results of operations.

Environmental Litigation

State of Connecticut vs. Xcel Energy Inc. et al. — In 2004, the attorneys general of eight states and New York City, as well as several environmental groups, filed lawsuits in U.S. District Court in the Southern District of New York against five utilities, including Xcel Energy, the parent company of SPS, to force reductions in carbon dioxide (CO2) emissions.  The other utilities include American Electric Power Co., Southern Co., Cinergy Corp. and Tennessee Valley Authority.  The lawsuits allege that CO2 emitted by each company is a public nuisance.  The lawsuits do not demand monetary damages.  Instead, the lawsuits ask the court to order each utility to cap and reduce its CO2 emissions.  On Sept. 19, 2005, the court granted a motion to dismiss on constitutional grounds.  On appeal in September 2009, the U.S. Court of Appeals for the Second Circuit reversed the lower court decision.  In August 2010, defendants filed a petition for review with the U.S. Supreme Court.

Comer vs. Xcel Energy Inc. et al. — In 2006, Xcel Energy, the parent company of SPS, received notice of a purported class action lawsuit filed in U.S. District Court in the Southern District of Mississippi.  The lawsuit names more than 45 oil, chemical and utility companies, including Xcel Energy, as defendants and alleges that defendants’ CO2 emissions “were a proximate and direct cause of the increase in the destructive capacity of Hurricane Katrina.”  Plaintiffs allege negligence and public and private nuisance and seek damages related to the loss resulting from the hurricane.  Xcel Energy believes this lawsuit is without merit and intends to vigorously defend itself against these claims.  In August 2007, the court dismissed the lawsuit in its entirety against all defendants on constitutional grounds.  Plaintiffs filed a notice of appeal to the U.S. Court of Appeals for the Fifth Circuit.  In October 2009, the U.S. Court of Appeals for the Fifth Circuit reversed the district court decision, in part, concluding that the plaintiffs pleaded sufficient facts to overcome the constitutional challenges that formed the basis for dismissal by the district court.  A subsequent petition by defendants, including Xcel Energy, for en banc review was granted.  On May 28, 2010, the U.S. Court of Appeals for the Fifth Circuit ruled that it lacked an en banc quorum of nine active members to hear the case.  It dismissed the appeal, which resulted in the reinstatement of the district court’s opinion dismissing the case.  Plaintiffs subsequently filed with the U.S. Supreme Court a writ of mandamus, which is a procedure requesting the court to order the Fifth Circuit to review plaintiffs’ earlier appeal.  Defendants intend to oppose this request.

12

Native Village of Kivalina vs. Xcel Energy Inc. et al. — In 2008, the City and Native Village of Kivalina, Alaska, filed a lawsuit in U.S. District Court for the Northern District of California against Xcel Energy, the parent company of SPS, and 23 other utilities, oil, gas and coal companies.  Plaintiffs claim that defendants’ emission of CO2 and other GHGs contribute to global warming, which is harming their village.  Xcel Energy believes the claims asserted in this lawsuit are without merit and joined with other utility defendants in filing a motion to dismiss on June 30, 2008.  In October 2009, the U.S. District Court dismissed the lawsuit on constitutional grounds.  In November 2009, plaintiffs filed a notice of appeal to the U.S. Court of Appeals for the Ninth Circuit.  All briefs related to this appeal have been filed.  It is unknown when the Ninth Circuit will render a final opinion.

7. Short-Term Borrowings and Other Financing Instruments

Commercial Paper — At Sept. 30, 2010 and Dec. 31, 2009, SPS had no commercial paper outstanding.  The total commercial paper available for issuance was $248 million.

Money Pool — Xcel Energy and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings from the utility subsidiaries between each other.  The holding company may make investments in the utility subsidiaries at market-based interest rates; however, the utility money pool arrangement does not allow the utility subsidiaries to make investments in the holding company.

The following table presents the money pool investments (borrowings) for SPS:

(Millions of Dollars)	Sept. 30, 2010			Dec. 31, 2009
Money pool (borrowings) investments	$	(61	)	$	77
Weighted average interest rate		0.35	%		0.36	%
Money pool borrowing limit	$	100		$	100

8. Long-Term Borrowings and Other Financing Instruments

In February 2010, SPS redeemed its $25.0 million pollution control obligations, securing pollution control revenue bonds, due July 1, 2016.

9.  Derivative Instruments and Fair Value Measurements

SPS may enter into derivative instruments, including forward contracts, futures, swaps and options, to reduce risk in connection with changes in interest rates and electric utility commodity prices.

Short-Term Wholesale and Commodity Trading Risk — SPS conducts an immaterial amount of short-term wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy related instruments.  SPS’ risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the activities governed by the policy.

Interest Rate Derivatives — SPS may enter into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for a specific period.  These derivative instruments are generally designated as cash flow hedges for accounting purposes.

At Sept. 30, 2010, accumulated other comprehensive losses related to interest rate derivatives included $0.2 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings.

Accumulated other comprehensive losses related to interest rate derivatives reclassified into earnings during the three months ended Sept. 30, 2010 and Sept. 30, 2009 were $0.1 million and $0.3 million, respectively.  Accumulated other comprehensive losses related to interest rate derivatives reclassified into earnings during the nine months ended Sept. 30, 2010 and Sept. 30, 2009 were $0.2 million and $0.8 million, respectively.

Commodity Derivatives — SPS may enter into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric utility operations.  This could include the purchase or sale of energy or energy-related products.  At Sept. 30, 2010 and Dec. 31, 2009, SPS held no commodity derivatives.  Changes in the fair value of non-trading commodity derivative instruments are recorded in other comprehensive income or deferred as a regulatory asset or liability.  The classification as a regulatory asset or liability is based on the commission approved regulatory recovery mechanisms.

13

The following table shows the major components of derivative instruments valuation in the balance sheets:

	Sept. 30, 2010				Dec. 31, 2009
(Thousands of Dollars)	Derivative Instruments Valuation - Assets		Derivative Instruments Valuation - Liabilities		Derivative Instruments Valuation - Assets		Derivative Instruments Valuation - Liabilities
Long-term purchased power agreements	$	74,599	$	49,492	$	76,551	$	52,242

In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting contained in ASC 815 Derivatives and Hedging, SPS began recording several long-term purchased power agreements at fair value due to accounting requirements related to underlying price adjustments.  As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities.  During 2006, SPS qualified these contracts under the normal purchase exception.  Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

Financial Impact of Qualifying Cash Flow Hedges — The impact of qualifying interest rate cash flow hedges on SPS’ accumulated other comprehensive income, included as a component of common stockholder’s equity, is detailed in the following table:

	Three Months Ended Sept. 30,
(Thousands of Dollars)	2010			2009
Accumulated other comprehensive loss related to cash flow hedges at July 1	$	(1,762	)	$	(5,239	)
After-tax net realized losses on derivative transactions reclassified into earnings		44			159
Accumulated other comprehensive loss related to cash flow hedges at Sept. 30	$	(1,718	)	$	(5,080	)

	Nine Months Ended Sept. 30,
(Thousands of Dollars)		2010			2009
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(1,847	)	$	(5,559	)
After-tax net realized losses on derivative transactions reclassified into earnings		129			479
Accumulated other comprehensive loss related to cash flow hedges at Sept. 30	$	(1,718	)	$	(5,080	)

Fair Value Measurements

ASC 820 Fair Value Measurements and Disclosures provides a single definition of fair value and requires certain disclosures about assets and liabilities measured at fair value. A hierarchal framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance. The three levels in the hierarchy are as follows:

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reported date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices.

Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reported date.  The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with models using highly observable inputs.

Level 3 — Significant inputs to pricing have little or no observability as of the reported date.  The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation.

SPS had no assets or liabilities measured at fair value on a recurring basis as of Sept. 30, 2010 and Dec. 31, 2009.

14

10.  Financial Instruments

The estimated fair values of SPS’ recorded financial instruments are as follows:

	Sept. 30, 2010				Dec. 31, 2009
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Other investments	$	247	$	247	$	263	$	263
Long-term debt		897,687		1,019,592		922,447		977,029

The fair value of cash and cash equivalents, notes and accounts receivable, notes and accounts payable and short-term debt are not materially different from their carrying amounts because of the short-term nature of these instruments and/or because the stated rates approximate market rates.  The fair value of SPS’ long-term investments are estimated based on quoted market prices for those or similar investments.  The fair value of SPS’ long-term debt is estimated based on the quoted market prices for the same or similar issues or the current rates for debt of the same remaining maturities and credit quality.

The fair value estimates presented are based on information available to management as of Sept. 30, 2010 and Dec. 31, 2009.  These fair value estimates have not been comprehensively revalued for purposes of these financial statements since that date and current estimates of fair value may differ significantly.

Letters of Credit — SPS uses letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations.  At Sept. 30, 2010 there were no letters of credit outstanding.  At Dec. 31, 2009, there were $10.0 million of letters of credit outstanding.  The contract amounts of these letters of credit approximate their fair values and are subject to fees determined in the marketplace.

11. Other Income (Expense), Net

Other income (expense), net, consisted of the following:

	Three Months Ended Sept. 30,						Nine Months Ended Sept. 30,
(Thousands of Dollars)	2010			2009			2010			2009
Interest income (expense)	$	71		$	(135	)	$	168		$	57
Other nonoperating income		-			23			11			28
Insurance policy expense		(153	)		(233	)		(148	)		(377	)
Other nonoperating expense		-			(193	)		-			(204	)
Other income (expense), net	$	(82	)	$	(538	)	$	31		$	(496	)

12.  Segment Information

SPS has one reportable segment.  SPS operates in the regulated electric industry, providing wholesale and retail electric service in the states of Texas and New Mexico.  Revenues from external customers were $467.4 million and $397.1 million for the three months ended Sept. 30, 2010 and 2009, respectively, and $1,247.4 million and $1,094.2 million for the nine months ended Sept. 30, 2010 and 2009, respectively.

13.  Comprehensive Income

The components of total comprehensive income are shown below:

	Three Months Ended Sept. 30,				Nine Months Ended Sept. 30,
(Thousands of Dollars)	2010		2009		2010		2009
Net income	$	39,189	$	37,415	$	71,284	$	63,405
Other comprehensive income:
After-tax net realized losses on derivative transactions reclassified into earnings		44		159		129		479
Comprehensive income	$	39,233	$	37,574	$	71,413	$	63,884

15

14.  Benefit Plans and Other Postretirement Benefits

Pension and other postretirement benefit disclosures below generally represent Xcel Energy consolidated information unless specifically identified as being attributable to SPS.

Components of Net Periodic Benefit Cost (Credit)

	Three Months Ended Sept. 30,
	2010			2009			2010			2009
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Xcel Energy Inc.
Service cost	$	18,286		$	16,365		$	1,002		$	1,166
Interest cost		41,253			42,448			10,695			12,603
Expected return on plan assets		(58,080	)		(64,135	)		(7,132	)		(5,694	)
Amortization of transition obligation		-			-			3,611			3,611
Amortization of prior service cost (credit)		5,165			6,155			(1,233	)		(681	)
Amortization of net loss		12,078			3,114			2,910			4,832
Net periodic benefit cost		18,702			3,947			9,853			15,837
Costs not recognized and additional cost recognized due to the effects of regulation		(6,630	)		(723	)		972			972
Net benefit cost recognized for financial reporting	$	12,072		$	3,224		$	10,825		$	16,809
SPS
Net benefit cost (credit) recognized for financial reporting	$	1,448		$	(1,661	)	$	900		$	1,250
	Nine Months Ended Sept. 30,
		2010			2009			2010			2009
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Xcel Energy Inc.
Service cost	$	54,860		$	49,095		$	3,005		$	3,499
Interest cost		123,758			127,343			32,085			37,809
Expected return on plan assets		(174,239	)		(192,404	)		(21,397	)		(17,082	)
Amortization of transition obligation		-			-			10,833			10,833
Amortization of prior service cost (credit)		15,493			18,464			(3,699	)		(2,044	)
Amortization of net loss		36,236			9,342			8,732			14,497
Net periodic benefit cost		56,108			11,840			29,559			47,512
Costs not recognized and additional cost recognized due to the effects of regulation		(20,270	)		(2,169	)		2,918			2,918
Net benefit cost recognized for financial reporting	$	35,838		$	9,671		$	32,477		$	50,430
SPS
Net benefit cost (credit) recognized for financial reporting	$	4,345		$	(4,983	)	$	2,701		$	3,750

16

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Discussion of financial condition and liquidity for SPS is omitted per conditions set forth in general instructions H (1) (a) and (b) of Form 10-Q for wholly owned subsidiaries. It is replaced with management’s narrative analysis of the results of operations set forth in general instructions H (2) (a) of Form 10-Q for wholly owned subsidiaries (reduced disclosure format).

Forward-Looking Statements

The following discussion and analysis by management focuses on those factors that had a material effect on SPS’ financial condition, results of operations, and cash flows during the periods presented, or are expected to have a material impact in the future. It should be read in conjunction with the accompanying unaudited financial statements and the related notes to the financial statements.  Due to the seasonality of SPS’ electric sales, such interim results are not necessarily an appropriate base from which to project annual results.  Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we do not undertake any obligation to update them to reflect changes that occur after that date. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including the availability of credit and its impact on capital expenditures and the ability of SPS to obtain financing on favorable terms; business conditions in the energy industry; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by SPS; unusual weather; effects of geopolitical events, including war and acts of terrorism; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric market; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; environmental laws and regulations; actions of accounting regulatory bodies; the items described under Factors Affecting Results of Continuing Operations; and the other risk factors listed from time to time by SPS in reports filed with the SEC, including “Risk Factors” in Item 1A of SPS’ Form 10-K for the year ended Dec. 31, 2009, and Item 1A and Exhibit 99.01 to this Quarterly Report on Form 10-Q for the quarter ended Sept. 30, 2010.

Market Risks

SPS is exposed to market risks, including changes in commodity prices and interest rates, as disclosed in Item 7A, Quantitative and Qualitative Disclosures About Market Risk, in its Annual Report on Form 10-K for the year ended Dec. 31, 2009.  Commodity price and interest rate risks for SPS are mitigated in most jurisdictions due to cost-based rate regulation.

Distress in the financial markets may impact the fair value of the debt and equity securities in pension and postretirement health care plan trusts, as well as SPS’s ability to earn a return on short-term investments of excess cash.  As of Sept. 30, 2010, there have been no material changes to market risks from that set forth in SPS’s Annual Report on Form 10-K for the year ended Dec. 31, 2009.

Results of Operations

SPS’ net income was approximately $71.3 million for the first nine months of 2010, compared with net income of approximately $63.4 million for the first nine months of 2009.  The year to date increase is mainly due to electric sales growth, which was partially offset by higher O&M expenses.

Electric Revenues and Margin

Electric fuel and purchased power expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power.  The design of fuel and purchased power cost recovery mechanisms of the Texas and New Mexico jurisdictions may not allow for complete recovery of all expenses and, therefore, changes in fuel or purchased power costs can impact earnings.  The following tables detail the electric revenues and margin:

	Nine Months Ended Sept. 30,
(Millions of Dollars)	2010			2009
Electric revenues	$	1,247		$	1,094
Electric fuel and purchased power		(788	)		(673	)
Electric margin	$	459		$	421

17

The following tables summarize the components of the changes in electric revenues and electric margin:

Electric Revenues

(Millions of Dollars)	2010 vs. 2009
Fuel and purchased power cost recovery	$	123
Sales mix and demand revenue		12
Fuel cost allocation regulatory accruals		11
Retail sales increase (excluding weather impact)		7
Retail rate increases (New Mexico)		6
Estimated impact of weather		5
Non-fuel riders		(3	)
Other, net		(8	)
Total increase in electric revenues	$	153

Electric Margin

(Millions of Dollars)	2010 vs. 2009
Sales mix and demand revenue	$	12
Fuel cost allocation regulatory accruals		11
Retail sales increase (excluding weather impact)		7
Retail rate increases (New Mexico)		6
Estimated impact of weather		5
Non-fuel riders		(3	)
Transmission revenue, net of expense		(2	)
Other, net		2
Total increase in electric margin	$	38

Non-Fuel Operating Expense and Other Items

Other Operating and Maintenance Expenses — Other operating and maintenance expenses for the first nine months of 2010 increased $19.6 million, or 12.2 percent, compared to first nine months of 2009.  The following summarizes the components of the changes for the nine months ended Sept. 30:

(Millions of Dollars)	2010 vs. 2009
Higher employee benefit costs	$	9
Higher plant generation costs		4
Higher labor costs		3
Other, net (including contract labor and employee expenses)		4
Total increase in other operating and maintenance expenses	$	20

Allowance for Funds Used During Construction, Debt and Equity (AFUDC) —AFUDC decreased by approximately $0.5 million for the first nine months of 2010 compared with 2009.  This decrease was primarily due to lower AFUDC rates, primarily driven by lower interest rates.

Interest Charges — Interest charges for the first nine months of 2010 decreased by approximately $2.8 million, or 5.4 percent, compared with 2009.  The decrease was primarily due to retirement of long-term debt in March 2009.

18

Income Taxes — Income tax expense increased by $9.2 million for the first nine months of 2010, compared with the first nine months of 2009.  The increase in income tax expense was primarily due to an increase in pretax income and a write-off of tax benefits previously recorded for Medicare Part D subsidies.  The effective tax rate was 39.8 percent for the first nine months of 2010, compared with 37.4 percent for the same period in 2009.  The higher effective tax rate for the first nine months of 2010 was primarily due to a higher forecasted annual effective tax rate and the write-off of tax benefit for Medicare Part D subsidies in 2010.  Without this write-off, the effective tax rate for the first nine months of 2010 would have been 38.2 percent.

Factors Affecting Results of Continuing Operations

Public Utility Regulation

Jones Certificate of Convenience and Necessity (CCN) — SPS applied for a CCN to build a gas-fired combustion turbine generating unit at SPS’ existing Jones Station in Lubbock, Texas with the PUCT, which approved the CCN in August 2010.  A similar CCN approval application was made with the NMPRC.  The parties reached a settlement recommending approval that was filed with the NMPRC on Oct. 7, 2010.  A final order is expected in December 2010.

New Mexico Energy Efficiency Disincentive Rulemaking— During the 2008 New Mexico legislative session, increased energy efficiency goals and more affirmative disincentive language were adopted.  In 2010, the NMPRC adopted an amended rule incorporating the legislative changes.  The rule has an interim mechanism that provides for recovery of disincentives and recently required utilities to file permanent rate design or other means of removing disincentives by July 1, 2010.

In June 2010, SPS filed its application for approval of its interim incentive.  That same month, an appeal of the rule was filed by the Attorney General and the New Mexico Industrial Energy Consumers with the New Mexico Supreme Court.  SPS and the intervenors have reached a settlement agreement for the 2010 and 2011 disincentives and incentives of $3.3 million.  The settlement agreement is independent of the NMPRC’s ruling.  A final order is expected in December 2010.  In July 2010, SPS filed its application regarding permanent solutions to removing disincentives and requested direct lost margin recovery.  A hearing in this case is scheduled for March 8, 2011.

Solar Contract Approval —In December 2009, SPS entered into five solar energy purchased power agreements (PPAs) with five separate entities associated with SunEdision, LLC (SunE), for the procurement of solar energy and associated renewable energy credits to meet its solar diversity requirements.  The SunE PPAs involve five facilities, each consisting of 10 MW of capacity for a term of 20 years.

In January 2010, SPS filed a request with the NMPRC to approve SPS’s SunE PPAs and authorize SPS to recover the costs of the PPAs from its New Mexico customers.  In September 2010, the NMPRC approved the SunE PPAs and SPS’ proposed cost recovery.

New Mexico GHG Regulations — SPS may face the future risk of regulation of CO2 emissions from proposed rules in New Mexico.  The NMED and New Energy Economy, a non-governmental environmental advocacy organization, have each proposed rules before New Mexico’s Environmental Improvement Board (EIB) to limit and reduce GHGs, including CO2 emissions from power plants.  The rulemaking process for both proposals is ongoing with a final decision by the EIB likely by the end of 2010.  If either proposed rule is adopted in New Mexico, SPS may face additional costs for compliance, possibly including the purchase of carbon offsets or the cost of CO2 emission reductions in the New Mexico portion of the SPS system.  Compliance costs for these reductions or offsets may increase electricity rates to New Mexico customers.  While regulated utilities generally recover costs resulting from regulatory requirements, SPS may not recover all costs related to complying with the regulatory requirements imposed on us under the proposed rules.  The effect on the financial condition of SPS is uncertain, due to the lack of certainty in the final rules, and also due to the relatively small proportion of SPS total greenhouse gases that are emitted in New Mexico.  If the EIB adopts one or both of the proposed rules, the anticipated compliance date is 2012.

Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, accounting practices and certain other activities of SPS, including enforcement of North American Electric Reliability Corporation (NERC) mandatory electric reliability standards. State and local agencies have jurisdiction over many of SPS’ activities, including regulation of retail rates and environmental matters. See additional discussion in the summary of recent federal regulatory developments and public utility regulation sections of the SPS Annual Report on Form 10-K for the year ended Dec. 31, 2009.  In addition to the matters discussed below, see Note 5 to the financial statements for a discussion of other regulatory matters.

19

Southwest Power Pool, Inc. (SPP) Transmission Cost Recovery — The SPP transmission tariff currently establishes the mechanism for recovering costs associated with transmission projects.  Currently, for base plan transmission projects, one-third of the costs are collected on an SPP region-wide basis and the remaining two-thirds are recovered from individual pricing zone(s) in SPP using a power flow analysis.  For balanced portfolio projects, 100 percent of the costs are recovered on an SPP region-wide basis.  In March 2010, the SPP board approved the tariff filing for this cost allocation methodology as follows:

● For projects rated at a voltage level less than 100 KV, all costs would be recovered from the pricing zone of the project;

● For projects rated at a voltage level between 100 KV and 300 KV, one-third of the costs would be recovered on an SPP region-wide basis and two-thirds would be recovered from the pricing zone of the project; and

● For projects rated at a voltage level greater than 300 KV, 100 percent of costs would be recovered on an SPP region-wide basis.

The FERC approved the SPP transmission cost allocation plan, effective June 2010.  The SPP transmission cost allocation methodology will allow the costs of priority projects constructed in the SPS rate zone to be regionalized, but SPS will share in the costs of priority projects built in other SPP rate zones.

Electric Reliability Standards Compliance

Compliance Audits

In 2008, SPS filed a self-report with the SPP regional entity relating to failure to complete certain generation station battery tests, relay maintenance intervals and record keeping associated with certain Critical Infrastructure Protection (CIP) standards.  In 2009, SPS reached agreement with the SPP that would resolve all self reports by payment of a non-material penalty.  In April 2010, SPS executed a definitive settlement agreement.  The settlement agreement is pending approval at the NERC and will also need to be approved by the FERC.

In March 2010, the SPP conducted a compliance spot check to evaluate compliance with the NERC CIP standards, which were effective July 1, 2008.  The draft non-public report issued by the SPP in July 2010 found that that the SPS may not be in compliance with several of the CIP standards.  Xcel Energy, the parent company of SPS, provided comments on the draft report, disagreeing with many of the conclusions.  The regional entity audit function issued a non-public final report in August 2010 alleging violations of certain CIP requirements, including certain violations common to all Xcel Energy utility subsidiaries; at that time, the spot check report was transferred to the MRO enforcement function.  Xcel Energy continues to dispute the alleged violations and is working to resolve issues with the MRO enforcement functions.  The CIP spot check report findings related to SPS will then proceed to the SPP enforcement process.  To what extent the SPP regional entity or NERC may seek to impose penalties for potential violations is unknown at this time.

Item 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

SPS maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure. As of Sept. 30, 2010, based on an evaluation carried out under the supervision and with the participation of SPS’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that SPS’s disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

No change in SPS’ internal control over financial reporting has occurred during the most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, SPS’ internal control over financial reporting.

Part II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

In the normal course of business, various lawsuits and claims have arisen against SPS. After consultation with legal counsel, SPS has recorded an estimate of the probable cost of settlement or other disposition for such matters.

20

Additional Information

See Notes 5 and 6 of the financial statements in this Quarterly Report on Form 10-Q for further discussion of legal proceedings, including Regulatory Matters and Commitments and Contingent Liabilities, which are hereby incorporated by reference. Reference also is made to Item 3 and Notes 13 and 14 of SPS’ financial statements in its Annual Report on Form 10-K for the year ended Dec. 31, 2009 for a description of certain legal proceedings presently pending.

Item 1A — RISK FACTORS

Except to the extent updated or described below, SPS’ risk factors are documented in Item 1A of Part I of its Annual Report on Form 10-K for the year ended Dec. 31, 2009, which is incorporated herein by reference.

We may be subject to legislative and regulatory responses to climate change, with which compliance could be difficult and costly.

Legislative and regulatory responses related to climate change and new interpretations of existing laws through climate change litigation create financial risk. Increased public awareness and concern may result in more regional and/or federal requirements to reduce or mitigate the effects of GHGs. Numerous states have announced or adopted programs to stabilize and reduce GHG, and federal legislation has been introduced in both houses of Congress. Our electric generating facilities are likely to be subject to regulation under climate change laws introduced at either the state or federal level within the next few years.

The EPA has taken steps to regulate GHGs under the Clean Air Act.  On Dec. 7, 2009, the EPA issued a finding that GHG emissions endanger public health and welfare, and that motor vehicle emissions contribute to the GHGs in the atmosphere. This endangerment finding creates a mandatory duty for the EPA to regulate GHGs from light duty motor vehicles. The EPA finalized GHG efficiency standards for light duty vehicles in spring 2010 and has promulgated  permitting requirements for GHGs for large new and modified stationary sources, such as power plants.  These regulations will become applicable in 2011.  We are also currently a party to climate change lawsuits and may be subject to additional climate change lawsuits, including lawsuits similar to those described in Note 6, Commitments and Contingent Liabilities, in the notes to the financial statements. While we believe such lawsuits are without merit, an adverse outcome in any of these cases could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant. Such payments or expenditures could affect results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

Many of the federal and state climate change legislative proposals, such as the American Clean Energy and Security Act and the proposed Kerry-Lieberman legislation, use a cap and trade policy structure, in which GHG emissions from a broad cross-section of the economy would be subject to an overall cap. Under the proposals, the cap becomes more stringent with the passage of time. The proposals establish mechanisms for GHG sources, such as power plants, to obtain “allowances” or permits to emit GHGs during the course of a year. The sources may use the allowances to cover their own emissions or sell them to other sources that do not hold enough emission allowances for their own operations. Proponents of the cap and trade policy believe it will result in the most cost effective, flexible emission reductions. There are many uncertainties, however, regarding when and in what form climate change legislation will be enacted. The impact of legislation and regulations, including a cap and trade structure, on us and our customers will depend on a number of factors, including whether GHG sources in multiple sectors of the economy are regulated, the overall GHG emissions cap level, the degree to which GHG offsets are allowed, the allocation of emission allowances to specific sources and the indirect impact of carbon regulation on natural gas and coal prices. While we do not have operations outside of the United States, any international treaties or accords could have an impact to the extent they lead to future federal or state regulations. Another important factor is our ability to recover the costs incurred to comply with any regulatory requirements that are ultimately imposed. We may not recover all costs related to complying with regulatory requirements imposed on us. If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material adverse effect on our results of operations.

21

Item 6. EXHIBITS

* Indicates incorporation by reference

3.01*	Amended and Restated Articles of Incorporation dated Sept. 30, 1997 (Exhibit 3(a)(2) to Form 10-K for the year ended Dec. 31, 1997 (file no. 001-03789) dated March 3, 1998).
3.02*	By-laws dated Sept. 29, 1997 (Exhibit 3(b)(2) to Form 10-K for the year ended Dec. 31, 1997 (file no. 001-03789) dated March 3, 1998).
31.01	Principal Executive Officer’s and Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01	Statement pursuant to Private Securities Litigation Reform Act of 1995.

22

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on Nov. 1, 2010.

Southwestern Public Service Company

(Registrant)

/s/ TERESA S. MADDEN

Teresa S. Madden

Vice President and Controller

/s/ DAVID M. SPARBY

David M. Sparby

Vice President and Chief Financial Officer

23